CALGARY, ALBERTA--(Marketwire - July 30,
2007) - NAL Oil & Gas Trust (TSX:NAE.UN) today announced financial
and operational results that reflect continued strong performance during
the second quarter ended June 30, 2007. All amounts are in Canadian
dollars unless otherwise stated.
President and Chief Executive Officer Andrew Wiswell is encouraged
by NAL's strong performance and continued positive momentum in the
second quarter which were achieved despite wet weather and planned
turnarounds. "Through focused effort by our operating teams, we were
able to exceed our production guidance again in the second quarter",
said Mr. Wiswell, "and we did it while spending less capital than last
year. Our operating costs remained below guidance and we maintained our
strong balance sheet, which is one of the best among the energy trusts.
Based on our results to date, we have decided to increase our production
guidance and narrow our operating cost target range for 2007, while
reducing planned capital spending."
SECOND QUARTER HIGHLIGHTS
- Production averaged 18,946 barrels of oil equivalent per day
(boe/d) during the second quarter of 2007, exceeding our guidance range.
This performance was achieved as a result of a strong contribution from
our base production, the tie-in of volumes that were 'behind pipe' in
the first quarter, and a lower than expected impact of plant turnarounds
during the three month period. Our production mix remains relatively
consistent over the first 6 months of the year, weighted 59% to Crude
and NGL's and 41% to Natural Gas. We are increasing our guidance on
production volumes to 19,100 - 19,300 boe/d for the full year.
- Capital expenditures are now forecast to be $101 million compared
to a budget of $106 million, driven primarily by lower natural gas
related activity. We are carefully managing our capital by focusing on
projects that can deliver an attractive rate of return in the current
commodity price environment. Capital spending during the quarter was
$18.9 million versus $27.1 million in the first quarter, for a total of
$46.0 million during the first half of 2007.
- NAL drilled five commercial oil wells and two water injection
wells in Southeast Saskatchewan during the quarter. So far this year the
Trust has drilled 46 gross (18.8 net) wells, including the two
injection wells, at a 100 percent success rate. NAL has two rigs under
contract in Southeast Saskatchewan with plans to drill continuously for
the rest of the year, and drier conditions have now permitted a
resumption of drilling and construction activity in Alberta.
- Improved crude oil differentials offset the impact of a rising
Canadian dollar during the second quarter. NAL's realized prices were
largely unchanged in the quarter at $55.73 per boe versus $54.83 per boe
in the second quarter of 2006.
- Hedging gains totaled $848,000 or $0.49 per boe during the second
quarter and $3.1 million or $0.90 per boe for the first six months of
the year, augmenting the realized price. The Trust has approximately 45
percent of its net (after royalty) production volumes hedged for the
balance of this year, and has been scaling in hedge positions for early
2008.
- NAL's operating costs continue to be lower than the Trust industry
average. Our ongoing focus on cost management allowed us to reduce
operating costs to $8.67 per boe in the second quarter from $9.63 per
boe a year ago.
- NAL generated $54.1 million in cash flow or $0.69 per unit during
the second quarter, exceeding consensus expectations. The Trust paid out
$37.9 million in distributions to unit holders, for a payout ratio of
70 percent, unchanged from the first quarter.
- NAL's balance sheet remains strong with net debt at the end of the
second quarter of $222.4 million, representing a multiple of 1.0 times
trailing twelve months cash flow. With $325 million in available lines
of credit, the Trust has approximately $90 million in available bank
lines with which to fund ongoing operations and property acquisitions.
Outlook and Guidance
NAL is revising its guidance for 2007 on the basis of strong first
half results. Production volumes are now expected to exceed the high end
of the earlier guidance range. Operating costs should come in at the
lower end of the range provided earlier this year, although they are
expected to increase in the third quarter as a result of scheduled plant
turnarounds.
January 2007 First Half 2007 Revised 2007
Guidance Actual Guidance
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Production (boe/d) 18,500 - 19,000 19,183 19,100 - 19,300
Operating Costs ($/boe) 8.90 - 9.40 8.37 8.90 - 9.10
General & Admin ($/boe) 1.75 - 1.95(1) 2.01(1) 1.75 - 1.95(1)
Capital Spending ($MM) 106 46 101
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(1) Excluding special retention bonus (see G&A Expenses) and unit based
compensation.
At 8:00 am MDT (10:00 am EDT) on Monday, July 30, 2007 NAL will
conduct a conference call to discuss its second quarter results. Mr.
Andrew Wiswell, President and CEO, will host the conference call with
other members of the Management Team. The call will be open to analysts,
investors and all interested parties. If you wish to participate, call
1-866-226-1793 toll free across North America. A recorded playback of
the call will be available until August 3, 2007 by dialing
1-416-695-5800 or 1-800-408-3053 and entering pass code 3230734#.
The conference call will also be accessible by webcast at
http://events.onlinebroadcasting.com/nal/072707/index.php
When converting natural gas to equivalent barrels of oil within this
report, NAL uses the widely recognized standard of 6 thousand cubic
feet (Mcf) to one barrel of oil (boe). However, boe's may be misleading,
particularly if used in isolation. A boe conversion ratio of 6 Mcf : 1
bbl is based on an energy equivalency conversion method primarily
applicable at the burner tip and does not represent a value equivalency
at the wellhead.
FINANCIAL AND OPERATING HIGHLIGHTS
(thousands of dollars, except per unit and boe data)
----------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
FINANCIAL
Gross revenue, net of
royalties $ 83,268(1) $ 77,988 $ 154,499(1) $ 159,260(1)
Net income (loss) 21,390(1) (5,357)(2) 38,100(1) 19,253(1)
Funds from operations 54,156 52,210 108,391 109,874
Distributions declared 37,877 43,268 75,483 85,865
Funds from operations
per unit 0.69 0.69 1.38 1.46
Distributions declared
per unit 0.48 0.57 0.96 1.14
Payout ratio 70% 83% 70% 78%
Average number of units
outstanding (000s) 78,824 75,869 78,543 75,210
Bank debt, net of working
capital excluding
derivative contracts 222,408 186,333 222,408 186,333
Capital expenditures 18,925 27,509 45,984 47,522
Costs per boe (6:1):
Operating $ 8.67 $ 9.63 $ 8.37 $ 8.71
General and administrative,
excluding special
retention bonus 2.10 2.00 2.01 1.67
General and administrative
special retention bonus 0.13 - 0.22 -
Unit-based incentive
compensation 0.40 0.34 0.19 0.69
Management fees - 0.35 - 0.38
OPERATING
Daily production
Oil (bbl) 9,068 8,959 9,196 9,254
Natural gas (Mcf) 46,942 48,861 47,328 50,390
Natural gas liquids (bbl) 2,055 1,910 2,099 1,941
Oil equivalent (boe - 6:1) 18,946 19,012 19,183 19,593
Average pricing, net of
transportation charges and
before hedging gains and
losses
Liquids:
WTI (US$/bbl) 65.03 70.70 61.60 67.11
NAL average oil (Cdn$/bbl) 67.18 71.35 64.37 65.88
NAL natural gas liquids
(Cdn$/bbl) 48.33 49.86 46.82 50.76
Natural gas:
AECO (Cdn$/Mcf) - daily spot 7.07 6.03 7.24 6.81
AECO (Cdn$/Mcf) - monthly 7.37 6.28 7.42 7.77
NAL natural gas Western
Canada (Cdn$/Mcf) 7.27 6.16 7.40 7.54
NAL natural gas Lake Erie
(Cdn$/Mcf) 8.99 7.73 9.88 8.55
NAL average natural gas
(Cdn$/Mcf) 7.40 6.30 7.59 7.63
NAL oil equivalent before
hedging gains (losses)
(Cdn$/boe - 6:1) 55.73 54.83 54.70 55.76
Average foreign exchange rate
(Cdn$/US$) 1.098 1.122 1.135 1.139
Operating netback before hedging
gains (losses) ($/boe) 35.04 34.14 34.44 34.87
Hedging gains per boe 0.49 0.37 0.90 0.25
Operating netback ($/boe) 35.53 34.51 35.34 35.12
----------------------------------------------------------------------------
(1) Includes unrealized gain (loss) on derivative contracts due to
implementation of new accounting standards, January 1, 2007 (see
Risk Management).
(2) Includes one time $27.2 million non-cash management contract
restructuring charge.
MANAGEMENT'S DISCUSSION AND ANALYSIS
The following discussion and analysis ("MD&A") should be read in
conjunction with the Interim Consolidated Financial Statements for the
three and six month periods ended June 30, 2007 and the audited
Consolidated Financial Statements and MD&A for the year ended
December 31, 2006 of NAL Oil & Gas Trust ("NAL" or the "Trust"). It
also contains information and opinions on the Trust's future outlook
based on currently available information. All amounts are reported in
Canadian dollars, unless otherwise stated. Where applicable, natural gas
has been converted to barrels of oil equivalent ("boe") based on a
ratio of six thousand cubic feet of natural gas to one barrel of oil.
The boe rate is based on an energy equivalent conversion method
primarily applicable at the burner tip and does not represent a value
equivalent at the wellhead. Use of boe in isolation may be misleading.
NON-GAAP FINANCIAL MEASURES
Throughout this discussion and analysis, Management uses the terms
operating netbacks, cash flow netbacks, funds from operations and funds
from operations per unit as they are considered useful supplemental
measures, as they provide an indication of the results generated by the
Trust's principal business activities. These terms do not have any
standardized meaning as prescribed by Canadian Generally Accepted
Accounting Principles ("GAAP"). Investors should be cautioned that these
measures should not be construed as an alternative to net income
determined in accordance with GAAP as an indication of NAL's
performance. NAL's method of calculating these measures may differ from
other income funds and companies and, accordingly, they may not be
comparable to measures used by other income funds and companies. NAL
calculates funds from operations prior to the change in non-cash working
capital related to operating activities, with the per unit amount
calculated using the weighted average units outstanding for the period.
The following table reconciles cash flow from operating activities to funds
from operations:
----------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Cash flow from operating
activities 56,021 60,221 108,987 129,018
Changes in non-cash working
capital (1,865) (8,011) (596) (19,144)
----------------------------------------------------------------------------
Funds from operations 54,156 52,210 108,391 109,874
----------------------------------------------------------------------------
FORWARD-LOOKING INFORMATION
This disclosure contains certain forward-looking statements that
involve substantial known and unknown risks and uncertainties, many of
which are beyond NAL's control, including: the impact of general
economic conditions in Canada and in the United States, industry
conditions, changes in laws and regulations including the adoption of
new environmental laws and regulations and changes in how they are
interpreted and enforced, increased competition, the lack of
availability of qualified operating or management personnel,
fluctuations in commodity prices, foreign exchange or interest rates,
stock market volatility and fluctuations in market valuations of
companies with respect to announced transactions and the final
valuations thereof, and the ability to obtain required approvals from
regulatory authorities. NAL's actual results, performance or achievement
could differ materially from those expressed in, or implied by, these
forward-looking statements and, accordingly, no assurances can be given
that any of the events anticipated by the forward-looking statements
will transpire or occur, or if any of them do so, what benefits,
including the amount of proceeds, that NAL will derive therefrom.
DEVELOPMENT ACTIVITIES
The Trust participated in the drilling of 5 (2.8 net) commercial
wells during the second quarter, with a success rate of 100%, and 2 (1.0
net) service wells. At the end of the second quarter, two rigs were
drilling oil targets in Saskatchewan, and one rig was drilling for gas
in the Hanna area of Alberta.
Second Quarter Drilling Activity
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Crude Natural Service Dry &
Oil Gas Wells Abandoned Total
---------------------------------------------------------
Gross Net Gross Net Gross Net Gross Net Gross Net
----------------------------------------------------------------------------
Operated wells 5.0 2.8 0 0 2.0 1.0 0 0 7.0 3.8
Non-operated wells 0 0 0 0 0 0 0 0 0 0
----------------------------------------------------------------------------
Total wells
drilled 5.0 2.8 0 0 2.0 1.0 0 0 7.0 3.8
----------------------------------------------------------------------------
YTD Drilling Activity
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Crude Natural Service Dry &
Oil Gas Wells Abandoned Total
---------------------------------------------------------
Gross Net Gross Net Gross Net Gross Net Gross Net
----------------------------------------------------------------------------
Operated wells 24 11.6 7.0 4.8 2.0 1.0 0 0 33 17.3
Non-operated wells 5.0 0.6 8.0 0.8 0 0 0 0 13 1.4
----------------------------------------------------------------------------
Total wells
drilled 29 12.2 15 5.6 2.0 1.0 0 0 46 18.8
----------------------------------------------------------------------------
Southeast Saskatchewan
All of the drilling activity in the second quarter was in S.E.
Saskatchewan including five successful horizontal oil wells (Alida,
Browning (2), Elswick, Midale) and two water injectors (Elswick). Water
injector conversions were completed in Rosebank with positive early time
response in the surrounding producing wells. Minor facilities projects
for header expansions and testing facilities were also executed.
Despite poor weather conditions during the quarter across Western
Canada, drilling and completion activity in Saskatchewan remained
generally on pace. All wells drilled during the quarter were tied-in and
producing at quarter-end. Two contracted rigs will be drilling
continuously across all of our Saskatchewan operating areas for the
remainder of the year.
Gas Focus Areas (Nevis, Lacombe, Hanna, Pine Creek, Lake Erie)
Wet conditions prevented access to planned drilling locations in
June, but better conditions in early July coupled with the use of a
coiled tubing drilling rig have allowed us to recover some lost time for
the remaining program. Construction was also affected in some areas,
with a 100 boe/d well behind pipe from first quarter still not tied-in
(Banff oil producer).
As well, Talisman, the operator of Lake Erie, in consultation with
NAL, decided to defer the 2007 summer drilling program into 2008. The
modest success of the 2006 program, together with commodity price
considerations, prompted the decision. 2007 capital will be directed to
several optimization projects, planned recompletions, as well as
completions and tie-ins carried over from the 2006 drilling program.
This deferral of capital will save approximately $3.0 million of 2007
spending compared to budget. A full drilling program is planned for the
2008 drilling season.
Tie-in work and commissioning of additional Lacombe facilities
brought on incremental behind pipe production late in the second
quarter. Horseshoe Canyon CBM drilling for the remainder of 2007 has
been reduced from 22 to 10 wells allowing us to defer some
infrastructure spending while fully utilizing existing gas gathering and
compression systems.
Several third party plant turnarounds were completed during May and
June with production outages as projected in the operating plan.
Central Alberta - (Sylvan Lake, Medicine River, Garrington, Westward Ho)
Poor weather was particularly troublesome in this region. Wet
conditions hampered most activities in the quarter with select
recompletions and minor facilities projects proceeding as planned. This
activity will be rescheduled to late July or early August. The NAL
Sylvan Lake Gas Plant completed a major turnaround in June as did other
third party facilities in the area that handle NAL production. Volume
outages were less than budgeted with some gas volumes successfully
redirected to other facilities, resulting in volumes being 70 boe/d
higher than plan. Downtime and costs were in line with forecasts as no
surprises were found with this scheduled maintenance activity.
CAPITAL EXPENDITURES
Capital expenditures for the quarter ended June 30, 2007 were
consistent with budget and totaled $18.9 million, compared with $27.5
million in the quarter ended June 30, 2006. For the six months ended
June 30, 2007 capital expenditures were on plan and totaled $46.0
million as compared to $47.5 million in the same period in 2006. Despite
modest drilling activity in the quarter, water injection conversions,
modifications to production equipment and selected well tie-ins were
completed. Planned optimization in Lake Erie, capital projects
associated with turnaround activity, and lease preparation for wells
that delayed to the third quarter, all played a part in spending being
on track with our budget.
NAL's capital spending outlook for full year 2007 will be modified
from $106 to $101 million ($92 million exploitation and development and
$9 million other capital) excluding acquisitions. This reduction
reflects $3 million for the deferral of the Lake Erie drilling program,
$1 million for miscellaneous capital items and $1 million for
capitalized G&A. These changes are not expected to affect production
for 2007.
Capital Expenditures ($000s)
----------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Drilling, completion and
production equipment $ 14,198 $ 14,503 $ 37,849 $ 29,054
Plant and facilities 2,143 2,446 4,395 4,090
Seismic 268 981 527 1,709
Land 106 4,968 357 5,409
Property acquisitions
(dispositions) - - (25) -
----------------------------------------------------------------------------
Total exploitation and
development 16,715 22,898 43,103 40,262
----------------------------------------------------------------------------
Office equipment 230 3,262(1) 274 3,262
Capitalized G&A 1,669 1,162 2,436 2,075
Capitalized unit-based
compensation 311 187 171 1,923
----------------------------------------------------------------------------
2,210 4,611 2,881 7,260
----------------------------------------------------------------------------
Total capital expenditures 18,925 27,509 45,984 47,522
----------------------------------------------------------------------------
(1) Includes $2.8 million in assets acquired as part of management agreement
restructuring
PRODUCTION
Production performance at 18,946 boe/d exceeded second quarter
guidance of 17,800- 18,300 boe/d. Momentum from a successful late first
quarter program, continued strong base performance, tie-ins of behind
pipe production and less impact from turnarounds were the contributing
factors delivering solid performance from all core areas.
Second quarter 2007 production is comparable with 19,012 boe/d for
the corresponding period in 2006 and slightly lower than the production
of 19,422 boe/d in first quarter 2007. A decline in production was
anticipated due to scheduled maintenance activity during the quarter.
For the six months ending June 30, 2007 average production also
decreased two percent to 19,183 boe/d from 19,593 boe/d for the same
period in 2006. Despite some industry curtailment in the Enbridge System
in Saskatchewan, NAL has experienced no shut-in volume for the six
months ended June 30, 2007.
For full year 2007, NAL's outlook is to average 19,100 - 19,300 boe
per day, an increase from the 18,500 - 19,000 boe/d guidance provided in
early 2007.
Average Daily Production Volumes
----------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Oil (bbl/d) 9,068 8,959 9,196 9,254
Natural gas (Mcf/d) 46,942 48,861 47,328 50,390
NGL's (bbl/d) 2,055 1,910 2,099 1,941
Oil equivalent (boe/d) 18,946 19,012 19,183 19,593
----------------------------------------------------------------------------
The Trust's production weighting was relatively unchanged from the
comparable period in 2006 with oil and natural gas liquids production
representing 59 percent of total production and natural gas 41 percent.
Production Weighting
----------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Oil 48% 47% 48% 47%
Natural gas 41% 43% 41% 43%
NGLs 11% 10% 11% 10%
----------------------------------------------------------------------------
REVENUE AND FUNDS FROM OPERATIONS
Gross revenue from oil, natural gas and natural gas liquids sales,
after transportation costs, totaled $96.1 million for the three months
ended June 30, 2007, a one percent increase over the second quarter of
2006. The increase is attributable to higher realized natural gas
prices. Compared to the second quarter of 2006, production remained
consistent and average commodity prices increased by one percent for the
second quarter of 2007, due to higher natural gas realized prices which
were offset partially by lower crude oil and NGL prices.
For the six month period ended June 30, 2007, revenue totaled $189.9
million, a decrease of four percent from the comparable period in 2006.
The decrease is attributable to a two percent decrease in production
and a two percent decrease in average commodity prices.
Funds from operations tracked revenues in the second quarter of
2007, up four percent in total from the second quarter of 2006 and
remains constant on a per unit basis at $0.69. For the six months ended
June 30, 2007, funds from operations decreased one percent from the
comparable period in 2006 and five percent from $1.46 to $1.38 on a per
unit basis due to issuing units under our Distribution Reinvestment
Program (DRIP).
----------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Revenue (1) ($000s) 96,081 94,861 189,920 197,746
$/boe 55.73 54.83 54.70 55.76
Funds from operations(2) ($000s) 54,156 52,210 108,391 109,874
$/boe 31.41 30.18 31.22 30.98
$/unit 0.69 0.69 1.38 1.46
----------------------------------------------------------------------------
(1) Oil, natural gas and liquid sales less transportation prior to
royalties, and excluding gain/loss on derivative contracts (see
Risk Management) .
(2) Represents cash flow from operating activities prior to the change in
non-cash working capital items.
Average Pricing
(net of transportation charges)
----------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Liquids
WTI (US$/bbl) 65.03 70.70 61.60 67.11
NAL average oil (Cdn$/bbl) 67.18 71.35 64.37 65.88
NAL natural gas liquids (Cdn$/bbl) 48.33 49.86 46.82 50.76
Hedging gains 0.85 - 1.77 -
Natural Gas (Cdn$/Mcf)
AECO - daily spot 7.07 6.03 7.24 6.81
AECO - monthly 7.37 6.28 7.42 7.78
NAL Western Canada natural gas 7.27 6.16 7.40 7.54
NAL Lake Erie natural gas 8.99 7.73 9.88 8.55
NAL average natural gas 7.40 6.30 7.59 7.63
Hedging gains 0.04 0.15 0.02 0.10
NAL Oil Equivalent before
hedging (Cdn$/boe - 6:1) 55.73 54.83 54.70 55.76
Average Foreign Exchange Rate
(Cdn$/US$) 1.098 1.122 1.135 1.139
----------------------------------------------------------------------------
OIL MARKETING
NAL sells its crude oil based on refiners' posted prices at
Edmonton, Alberta, and Cromer, Manitoba, adjusted for transportation and
the quality of each field battery. The refiners' posted prices are
influenced by the West Texas Intermediate ("WTI") benchmark price,
transportation costs, exchange rates and the supply/demand situation of
particular crude oil quality streams during the year.
NAL's second quarter average crude oil price per barrel, net of
transportation costs, was $67.18, as compared to $71.35 for the
comparable quarter of 2006. The decrease in realized price quarter over
quarter of six percent, or $4.17 per barrel, was primarily driven by an
eight percent decrease in WTI (US$/bbl), compared to the same period in
2006, to $65.03 per barrel. In addition, a strengthening Canadian dollar
resulted in a two percent decrease in the Cdn/US$ exchange rate
decreasing realized prices, but was offset by improved differentials of
NAL's crude compared to WTI priced in Canadian dollars.
For the second quarter of 2007, NAL's realized oil price was 94
percent of WTI at Edmonton in Canadian dollars, an increase of four
percent from the 90 percent for the corresponding period in 2006. The
increase in the second quarter of 2007 resulted from a narrower
differential occurring between WTI and Edmonton and Cromer posted
prices, due to greater demand for light crude in Western Canada during
that time frame. In the first quarter of 2006, differentials were wider
due to reduced demand for light sweet crude.
For the six months ended June 30, 2007, NAL's average oil price was
$64.37 per barrel, two percent lower than the comparable period in 2006.
The decrease in realized price was driven by an eight percent decrease
in WTI (US$/bbl) offset by a six percent increase in differentials to
WTI priced in Canadian dollars, from 86 percent in 2006 to 92 percent in
2007.
Natural gas liquids prices averaged $48.33 per barrel in the second
quarter of 2007, three percent lower than the second quarter of 2006.
For the six-month period ending June 30, 2007, natural gas liquids
pricing averaged $46.82, eight percent lower than the comparable period
in 2006.
NATURAL GAS MARKETING
Approximately 92 percent of NAL's current gas production is sold
under marketing arrangements tied to the Alberta monthly or daily spot
price ("AECO"), with the remaining eight percent tied to NYMEX or other
indexed referenced prices. Eight percent of the Trust's gas sales are
from its Lake Erie property and receives a higher price due to close
proximity to the Ontario and northeastern U.S. markets.
For the three months ended June 30, 2007, the Trust's gas sales
averaged $7.40/Mcf, compared to $6.30/Mcf for the comparable quarter in
2006, an increase of 17 percent. The quarter-over-quarter increase in
gas prices was attributable to a 17 percent increase in the benchmark
AECO prices. Natural gas sales from the Lake Erie property averaged
$8.99/Mcf in the second quarter of 2007, compared to $7.73/Mcf in 2006,
an increase of 16 percent.
For the six months ended June 30, 2007, NAL averaged $7.59/Mcf, a
one percent decrease from the $7.63 Mcf realized in the comparable
period of 2006. The decrease in realized price, despite an increase of
six percent in the AECO spot, is attributable to marketing a portion of
gas based on the monthly AECO, which decreased five percent. During the
six months ended June 30, 2007, the spread between the spot and monthly
AECO prices was $0.18 / Mcf compared to $0.97 / Mcf for the comparable
period in 2006.
RISK MANAGEMENT
NAL employs risk management practices to assist in managing cash
flows and support capital programs and distributions. NAL's management
is authorized to hedge up to 50 percent of its annual net production.
NAL's risk management programs are scaled in over time using a
combination of swaps and collars. During the first six months of 2007,
NAL had several financial WTI oil contracts and AECO natural gas
contracts in place.
The following is a summary of the realized gains and losses on risk
management contracts for the quarter and year to date:
----------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Average crude volumes hedged
(bbl/d) 2,300 2,700 2,300 2,600
Crude oil realized gain ($000's) $ 700 - $ 2,937 -
Gain per bbl hedged $ 3.34 - $ 7.06 -
Average natural gas volumes
hedged (GJ/d) 16,000 2,000 15,250 2,000
Natural gas realized gain ($000's)$ 148 $ 647 $ 185 $ 893
Gain per GJ hedged $ 0.10 $ 3.55 $ 0.07 $ 2.47
Average BOE hedged (boe/d) 5,113 3,052 4,981 2,952
Total realized gain ($000's) $ 848 $ 647 $ 3,122 $ 893
Gain per boe hedged $ 1.82 $ 2.33 $ 3.46 $ 1.67
----------------------------------------------------------------------------
The Trust has recorded the fair value of risk management contracts
on the balance sheet effective January 1, 2007 in accordance with new
accounting standards, issued by the Canadian Institute of Chartered
Accountants ("CICA"), addressing financial instruments and hedges. These
standards require all derivative instruments to be recorded on the
balance sheet at fair value, with changes in the fair value recognized
in net income unless specific hedge criteria are met. The Trust has not
designated any of its derivative contracts as effective accounting
hedges, even though the Trust considers all commodity contracts to be
effective economic hedges. Therefore, changes in the fair value of the
derivative contracts are recognized in net income for the period.
The loss on derivative contracts presented in the income statement
includes realized gains and losses, unrealized gains and losses since
January 1, 2007, and a reclassification from other comprehensive income.
The realized gain/loss represents actual cash settlements or receipts
under the respective contracts. The unrealized gain/loss represents the
change in the fair value of the contracts during the period. The
reclassification from other comprehensive income represents the
amortization of the fair value of the contracts on transition to the new
accounting standards, over the term of the contracts. On January 1,
2007, the fair value of the outstanding contracts of $4.5 million was
recorded as an asset with the offset being recorded in accumulated other
comprehensive income, a component of unitholders equity. The amount
recorded in accumulated other comprehensive income will be reclassified
to net income over the term of the derivative contracts, of which $1.4
million was reclassified in the second quarter of 2007 and $2.8 million
year to date.
Fair value is calculated at a point in time based on an
approximation of the amounts that would be received or paid to settle
these instruments, with reference to forward prices and market
valuations provided by third party sources. Accordingly, the magnitude
of the unrealized gain or loss will continue to fluctuate with changes
in commodity prices.
The fair value of the derivatives at June 30, 2007 was an asset of
$137,000. The fair value of $137,000 at June 30, 2007 was comprised of a
$2.7 million asset on gas contracts offset by a $2.6 million liability
on oil contracts.
Second quarter income of 2007 includes a $3.4 million unrealized
gain on derivatives resulting from the change in the fair value of the
derivative contracts during the quarter from a liability of $3.2 million
at March 31, 2007 to an asset of $137,000 at June 30, 2007. The $3.4
million unrealized gain in income was comprised of a $5.2 million
unrealized gain on natural gas contracts, offset by a $1.8 million
unrealized loss of crude oil contracts. The unrealized gain in the
second quarter income is primarily attributable to a decrease in natural
gas forward prices as compared to March 31, 2007.
For the six months ended June 30, 2007, income includes a $4.4
million loss resulting from the change in the fair value of the
derivative contracts during the six months. The unrealized loss was
comprised of a $5.3 million loss on oil contracts offset by a $0.9
million gain on gas contracts.
The gain/loss on derivative contracts for the quarter is as follows:
Gain (loss) on Derivative Contracts (000's)
----------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Unrealized gain (loss)
Crude oil contracts (1,811) - (5,340) -
Natural gas contracts 5,177 - 956 -
----------------------------------------------------------------------------
3,366 - (4,384) -
Realized gain 848 647 3,122 893
Reclassification from other
comprehensive income 1,394 - 2,773 -
----------------------------------------------------------------------------
5,608 647 1,511 893
----------------------------------------------------------------------------
Risk Management Contracts Summary
For the remainder of 2007, NAL has the following risk management contracts
outstanding:
---------------------------------------------------------------------------
CRUDE OIL NATURAL GAS
---------------------------------------------------------------------------
Swap (bbls) 328,100 Swap (GJ) 1,288,000
---------------------------------------------------------------------------
Swap (bbl/d) 1,783 Swap (GJ/d) 7,000
---------------------------------------------------------------------------
$US/bbl $67.76 $Cdn/GJ $7.16
---------------------------------------------------------------------------
Collars (bbls) 383,300 Collars (GJ) 1,656,000
---------------------------------------------------------------------------
Collars (bbl/d) 2,083 Collars (GJ/d) 9,000
---------------------------------------------------------------------------
$US/bbl $63.90 - $70.03 $Cdn/GJ $6.61 - $8.48
---------------------------------------------------------------------------
Total (bbls) 711,400 Total (GJ) 2,944,000
---------------------------------------------------------------------------
Total (bbl/d) 3,866 Total (GJ/d) 16,000
---------------------------------------------------------------------------
For 2008, NAL has the following risk management contracts outstanding:
---------------------------------------------------------------------------
CRUDE OIL NATURAL GAS
---------------------------------------------------------------------------
Swap (bbls) 63,700 Swap (GJ) 318,500
---------------------------------------------------------------------------
Swap (bbl/d) 174 Swap (GJ/d) 870
---------------------------------------------------------------------------
$US/bbl $72.07 $Cdn/GJ $8.24
---------------------------------------------------------------------------
Collars (bbls) 182,000 Collars (GJ) 455,000
---------------------------------------------------------------------------
Collars (bbl/d) 497 Collars (GJ/d) 1,243
---------------------------------------------------------------------------
$US/bbl $67.95 - $73.79 $Cdn/GJ $8.32 - $10.09
---------------------------------------------------------------------------
Total (bbls) 245,700 Total (GJ) 773,500
---------------------------------------------------------------------------
Total (bbl/d) 671 Total (GJ/d) 2,113
---------------------------------------------------------------------------
ROYALTY EXPENSES
Crown, freehold and overriding royalties were $20.7 million for the
three months ended June 30, 2007. Expressed as a percentage of gross
sales, before gain/loss on derivative contracts and transportation
costs, the net royalty rate was consistent with budget at 21.4 percent,
up from 20 percent for the same period last year.
On a year-to-date basis, royalties were $41.3 million, down from
$43.2 million in the comparable period of 2006. Expressed as a
percentage of gross sales, the royalty rate is consistent year-over-year
at 21.6 percent as compared to 21.7 percent in the prior year.
Royalty Expenses
----------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Net royalties ($000s) 20,717 19,135 41,277 43,191
As % of revenue(1) 21.4 20.0 21.6 21.7
$/boe 12.02 11.06 11.89 12.18
----------------------------------------------------------------------------
(1) Oil and natural gas and liquid sales before transportation and
gains/losses on derivative contracts.
OPERATING COSTS
For the quarter ended June 30, 2007, total operating costs were
lower compared to the similar period a year earlier. On a unit of
production basis, operating costs averaged $8.67/boe, a 10 percent
decrease from the $9.63/boe for the quarter ended June 30, 2006. Similar
trends are noted on a year-to-date basis with operating costs at
$8.37/boe for the six months ended June 30, 2007, compared with
$8.71/boe for 2006.
NAL owns and operates facilities associated with the majority of
production which translates into 80 percent of operating costs being
fixed. This proportion of fixed costs creates a similar operating cost
profile year over year independent of volume. Costs are traditionally
lower in the first four months of the year and rise significantly May
through September reflecting the high maintenance and turnaround
activity, and then decline through the fourth quarter.
Based on results to date, somewhat higher costs expected in the
third quarter and ongoing cost initiatives, full year performance is
projected to be at the lower end of guidance at $8.90- $9.10/boe.
Operating Costs
----------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Operating costs ($000s) 14,952 16,666 29,078 30,903
As % of revenue 15.6 17.4 15.3 15.6
$/boe 8.67 9.63 8.37 8.71
----------------------------------------------------------------------------
OPERATING NETBACK
For the quarter ended June 30, 2007, NAL's operating netback, before
realized gains on derivative contracts, was $35.04 per boe, an increase
of three percent from $34.14 for the quarter ended June 30, 2006. The
increase was due to higher revenue and lower operating costs, offset by
an increase in royalties. The increase in revenue of two percent was
primarily driven by a 17 percent increase in the average realized
natural gas price per Mcf, partially offset by lower crude oil and NGL
pricing per boe.
For the six month period ended June 30, 2007, operating netback
before hedging was $34.44 per boe, comparable with $34.87 per boe for
the comparable period in 2006. A two percent decrease in revenue per boe
was offset by decreases in royalties and operating costs per boe.
Operating Netback ($/boe)
----------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Revenue(1) 55.73 54.83 54.70 55.76
Royalties, net (12.02) (11.06) (11.89) (12.18)
Operating expenses (8.67) (9.63) (8.37) (8.71)
----------------------------------------------------------------------------
Operating netback, before hedging 35.04 34.14 34.44 34.87
Realized gains on derivative
contracts 0.49 0.37 0.90 0.25
----------------------------------------------------------------------------
Operating netback, after hedging 35.53 34.51 35.34 35.12
----------------------------------------------------------------------------
(1) Oil, natural gas and liquids sales less transportation
GENERAL AND ADMINISTRATIVE EXPENSES
General and administrative ("G&A") expenses include direct costs
incurred by the Trust plus the reimbursement of the Manager's G&A
expenses incurred on the Trust's behalf.
For the three months ended June 30, 2007, G&A expenses were $3.8
million, compared with $3.5 million in the comparable quarter in 2006.
In addition, $1.7 million of G&A costs relating to exploitation and
development activities were capitalized in the second quarter of 2007,
compared with $1.2 million in the second quarter of 2006.
For the six months ended June 30, 2007, G&A expenses increased
31 percent to $7.8 million from $5.9 million. In addition, on a
year-to-date basis $2.4 million of G&A costs relating to exploration
and development activities were capitalized, compared with $2.1 million
in 2006.
Total G&A increased $2.2 million from $8.0 million to $10.2
million in the first six months of 2007 due to increased compensation
costs associated with hiring, compensating and retaining staff. Included
in G&A expenses in 2007 is a retention bonus of $0.8 million
associated with an employee retention program established at year end
2006. This represents a $0.22 per boe charge in the first six months of
2007. Due to the program paying out in two equal installments, at June
30, 2007 and June 30, 2008, the expense for the remainder of 2007 will
be substantially less than for the six months ended June 30, 2007,
resulting in an expected average of $0.14 per boe for full year 2007.
While G&A excluding the retention bonus and unit-based compensation
plan is $2.01 per boe for the first six months of 2007, our full year
guidance remains unchanged at $1.75 - $1.95 per boe.
General and Administrative Expenses
----------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
G&A expenses ($000s)
G&A 3,614 3,464 6,975 5,928
Retention bonus 230 - 784 -
----------------------------------------------------------------------------
3,844 3,464 7,759 5,928
Capitalized G&A ($000s) 1,669 1,162 2,436 2,075
----------------------------------------------------------------------------
Total G&A ($000s) 5,513 4,626 10,195 8,003
Expensed G&A costs:
G&A, excluding retention bonus
($/boe) 2.10 2.00 2.01 1.67
Retention bonus ($/boe) 0.13 - 0.22 -
----------------------------------------------------------------------------
Total G&A expenses ($/boe) 2.23 2.00 2.23 1.67
As % of revenue 4.0 3.6 4.1 3.0
Per Trust unit ($) 0.05 0.05 0.10 0.08
----------------------------------------------------------------------------
UNIT-BASED INCENTIVE COMPENSATION PLAN
The employees of the Manager are all members of a unit-based
incentive plan (the "Plan"). The Plan results in employees receiving
cash compensation based upon the value and overall return of a specified
number of notional Trust units. The Plan consists of Restricted Trust
Units ("RTUs") and Performance Trust Units ("PTUs"). RTUs vest one third
on November 30 in each of three years after grant date. PTUs vest at
the end of three years. Distributions paid during the vesting period are
assumed to be reinvested in notional units on the date of distribution.
Upon vesting, the employee is entitled to a cash payout based on the
unit price at date of vesting of the units held. In addition, the PTUs
have a performance multiplier which is based on the Trust's performance
relative to its peers and may range from zero to two times the market
value of the notional units held at vesting.
During the second quarter of 2007, the Trust accrued $1.0 million of
unit-based incentive compensation charges as compared to $0.8 million
in the comparable quarter of 2006.
On a year-to-date basis, the Trust has accrued $0.8 million compared
to $4.4 million in the comparable period in 2006. The reduction in
unit-based compensation in 2007 is a reflection of a decrease in the
unit price and a decrease in the performance factors attached to the
PTUs. These reductions have resulted in the reversal of amounts accrued
prior to December 31, 2006 for units vesting in 2007 and 2008.
This calculation is made at the end of each quarter based on the
quarter ending unit price and performance factors. The compensation
charges relating to the units granted are recognized over the vesting
period based on the unit price, number of RTUs and PTUs outstanding, and
the expected performance multiplier. As a result, the expense recorded
in the accounts will fluctuate over time.
At June 30, 2007, the Trust has recorded a liability for unit-based
incentive compensation in the amount of $2.8 million, of which $1.2
million is expected to be paid in December 2007. The remaining balance
represents the long-term portion of the Trust's estimated liability for
the unit-based incentive plan as at June 30, 2007. This amount is
payable in December 2008 and December 2009.
Unit-Based Compensation
----------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Unit-based compensation:
Expensed ($000s) 688 595 664 2,433
Capitalized ($000s) 311 187 171 1,923
----------------------------------------------------------------------------
Total unit-based compensation
($000s) 999 782 835 4,356
Expensed unit-based compensation:
As % of revenue 0.7 0.6 0.3 1.2
$/boe 0.40 0.34 0.19 0.69
Per Trust unit ($) 0.01 0.01 0.01 0.03
----------------------------------------------------------------------------
MANAGEMENT CONTRACT AND FEES
The Trust is managed by NAL Resources Management Limited (the
"Manager"). The Manager is a wholly-owned subsidiary of Manulife
Financial Corporation ("MFC") and manages, on their behalf, NAL
Resources Limited ("NAL Resources"), another wholly-owned subsidiary of
MFC. NAL Resources and the Trust maintain ownership interests in many of
the same oil and natural gas properties, in which NAL Resources is the
joint operator. As a result, a significant portion of the net operating
revenues and capital expenditures during the year is based on joint
amounts from NAL Resources. These transactions are in the normal course
of joint operations and are measured using the fair value established
through the original transactions with third parties.
The Manager provides certain services pursuant to a Management
Contract. During the second quarter of 2006, the Trust paid $600,000 for
management fees and $1,350,000 for the six months ended June 30, 2006.
The management contract was restructured effective May 31, 2006, after
which no further management fees are payable.
The Trust paid $3.3 million (2006 - $1.9 million) for the
reimbursement of G&A expenses incurred by the Manager on behalf of
the Trust pursuant to the Management Contract during the second quarter
and $6.2 million (2006 - $3.6 million) year to date. The Trust also pays
the Manager its share of unit-based incentive compensation expense when
cash compensation is paid to employees under the terms of the Plan,
$2.2 million was paid in the first quarter of 2007 relating to notional
units that vested November 30, 2006.
INTEREST
Interest expense includes charges on borrowings plus standby fees on
the unused portion of the bank credit facility. NAL's average
outstanding bank debt for the second quarter of 2007 was $234.0 million,
compared to $192.4 million for the second quarter of 2006. NAL's
effective interest rate averaged 5.26 percent in 2007, compared with
4.79 percent in the second quarter of 2006. NAL's interest is at
floating rate. The increase in the rate from the second quarter of 2006
is attributable to rate increases in the market.
For the six months ended June 30, 2007 NAL's average debt was $228.8
million, compared to $201.1 million for the corresponding period in
2006. NAL's effective interest rate in 2007 averaged 5.2 percent
compared with 4.65 percent in 2006 due to rate increases in the market.
Interest expense for the second quarter increased by $0.8 million to
$3.1 million, as compared to $2.3 million for the comparable period in
2006, due to higher interest rates and increased average debt levels in
2007 compared to 2006. A similar trend is noted for the six months ended
June 30, 2007.
Interest and Bank Debt ($000s)
----------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Interest on bank debt 3,137 2,338 5,996 4,708
Bank debt outstanding at period
end 233,517 191,325 233,517 191,325
Net bank debt outstanding at period
end (1) 222,408 186,333 222,408 186,333
Net bank debt-to-cash flow ratio 1.02 0.78 1.02 0.78
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Net bank debt is bank debt net of working capital excluding derivative
contracts.
CASH FLOW NETBACK
For the quarter ended June 30, 2007, NAL's cash flow netback was
$31.08 per boe, a two percent increase from $30.47 for the comparable
period in 2006. The increase is attributable to a three percent increase
in operating netback, after hedging, and the elimination of management
fees, offset by higher G&A, retention bonus and interest.
A similar trend is noted for the six months ended June 30, 2007 as
the cash flow netback increased to $31.19 per boe from $31.05 in 2006.
Cash Flow Netback ($/boe)
----------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Operating netback, after hedging 35.53 34.51 35.34 35.12
Management fees - (0.35) - (0.38)
G&A expenses, excluding retention
bonus (2.10) (2.00) (2.01) (1.67)
Retention bonus (0.13) - (0.22) -
Unit-based incentive compensation (0.40) (0.34) (0.19) (0.69)
Interest (1.82) (1.35) (1.73) (1.33)
----------------------------------------------------------------------------
Cash flow netback 31.08 30.47 31.19 31.05
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Net bank debt is bank debt net of working capital excluding derivative
contracts.
DEPLETION, DEPRECIATION AND ACCRETION OF ASSET RETIREMENT OBLIGATION (DDA)
Depletion of oil and natural gas properties, including the
capitalized portion of the asset retirement obligation, and depreciation
of equipment are provided for on a unit-of-production basis using
estimated proved reserves volumes.
For the quarter ended June 30, 2007, depletion on property, plant
and equipment and accretion on the asset retirement obligation increased
by eleven percent over the comparable period in 2006 due to a twelve
percent increase in the DDA rate per boe of production.
Similar trends are noted for the six months ended June 30, 2007.
The DDA rate will fluctuate period over period depending on the
amount and type of capital expenditures and the amount of reserves
added.
Depletion, Depreciation and Accretion Expenses
----------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Depletion and depreciation
($000s) 34,822 31,236 69,250 64,141
Accretion of asset retirement
obligation 1,302 1,240 2,599 2,479
Total DDA ($000s) 36,124 32,476 71,849 66,620
DDA rate per boe ($) 20.95 18.77 20.69 18.79
----------------------------------------------------------------------------
----------------------------------------------------------------------------
TAXES
Taxes include federal and provincial capital and income taxes relating to the Trust and its subsidiary companies.
In the second quarter of 2007, NAL had a future income tax expense
of $2.5 million compared with a recovery of $1.2 million in the
corresponding period of the prior year.
For the six months ended June 30, 2007, NAL had a future income tax
recovery of $0.2 compared to a recovery of $1.2 million in 2006.
The Trust is a taxable trust and files a trust income tax return
annually. The Trust's taxable income consists of royalty income,
distributions from a subsidiary trust and interest and dividends from
other subsidiaries, less deductions for the Trust's G&A expenses,
Canadian Oil and Gas Property Expense, and issue costs. In addition,
Canadian Exploration Expense ("CEE"), Canadian Development Expense
("CDE") and Undepreciated Capital Cost ("UCC") are incurred and are
deducted by the Trust's subsidiaries. The Trust is taxable only on
remaining income, if any, that is not distributed to unitholders. The
Trust does not expect to incur any cash income taxes in 2007.
As at June 30, 2007, the Trust's (including all subsidiaries)
estimated tax pools (unaudited) available for deduction from future
taxable income approximate $506 million, of which approximately 42
percent represents COGPE and 31 percent UCC, with the remaining balance
represented by CEE, CDE, trust unit issue costs and non-capital loss
carry forwards.
On June 12, 2007, Bill C52, released by the Department of Finance on
December 21, 2006 to implement its October 31, 2006 announcement of the
changes to taxability of Income Trusts, received third reading in the
House of Commons. Under this legislation, distributions to unitholders
will not be deductible by publicly traded income trusts and, as a
result, the Trust will be taxed on its income similar to corporations.
As a result of passing third reading, these measures are now considered
substantially enacted for purposes of Canadian generally accepted
accounting principles. Accordingly, the Trust has measured, in the
second quarter of 2007, future income tax assets and liabilities
associated with this new tax. There is no impact, on the future tax
recognized in the financial statements, resulting from the
implementation of this tax legislation as it is expected that all
existing taxable temporary differences will reverse prior to January 1,
2011, the date the taxation changes take effect. Accordingly, all
taxable temporary differences have been recognized at a zero taxation
rate. The scheduling of the reversal of temporary differences is based
on management's best estimates and current assumptions, which may
change.
CAPITAL RESOURCES AND LIQUIDITY
The capital structure of the Trust is comprised of Trust units and bank debt.
As at June 30, 2007, NAL had 79,086,223 units outstanding, compared
with 77,971,268 units at December 31, 2006. The increase from December
31, 2006 is attributable to units issued under the distribution
reinvestment program.
For the six months ended June 30, 2007, the distribution
reinvestment ("DRIP") plan resulted in 1,114,955 units being issued at
an average price of $11.81 per unit for total proceeds of $13.2 million.
Unitholders electing to reinvest distributions or make optional cash
payments to acquire trust units from treasury under the DRIP may do so
at 95 percent of the average market price, with no additional fees or
commissions. The premium distribution reinvestment ("Premium DRIP") plan
allows unitholders to exchange such units for a cash payment from the
Plan Broker equal to 102 percent of the monthly distribution.
The Premium DRIP program has been suspended since March 10, 2006.
The participation rate in the regular DRIP averaged 17.5 percent
over the past six months, consistent with recent experience. The Trust
continues to monitor the participation in this plan in conjunction with
its capital requirements.
As at June 30, 2007 the Trust had bank debt of $222.4 million (net
of working capital excluding derivative contracts) compared with $223.1
million at December 31, 2006 and $186.3 million as at June 30, 2006. At
the end of the second quarter, the Trust had a net bank debt to equity
ratio of 0.51 and a net bank debt to twelve months trailing cash flow
ratio of 1.02.
The Trust renewed its credit facility during April 2007 and
increased the facility from $300 million to $325 million. The credit
facility is fully secured, extendible, and revolving and will revolve
until April 30, 2008, at which time it is extendible for a further
364-day revolving period upon agreement between the Trust and the bank
syndicate. The facility consists of a $315 million production facility
and a $10 million working capital facility. The credit facility is fully
secured by first priority security interests in all present and after
acquired properties and assets of the Trust and its subsidiary and
affiliated entities. The purpose of the facility is to fund property
acquisitions and capital expenditures. Principal repayments to the bank
are not required at this time. Should principal repayments become
mandatory, a portion of the cash flow otherwise available to unitholders
would be used to repay the facility in four equal quarterly
installments commencing May 2009.
Total bank debt amounted to $233.5 million at June 30, 2007 compared
with $220.8 million as at December 31, 2006. Of the debt outstanding at
June 30, 2007, $231.8 million was outstanding under the production
facility and $1.7 million under the working capital facility.
Capitalization
----------------------------------------------------------------------------
June 30, 2007 Dec. 31, 2006 June 30, 2006
----------------------------------------------------------------------------
Trust unit equity ($000s) 433,510 456,500 484,734
Bank debt ($000s) 233,517 220,785 191,325
Net bank debt (1) ($000s) 222,408 223,061 186,333
Net bank debt to equity 0.51 0.49 0.38
Net bank debt to trailing
12-month cash flow 1.02 1.01 0.78
Units outstanding (000s) 79,086 77,971 77,076
----------------------------------------------------------------------------
(1) Net bank debt is bank debt net of working capital, excluding derivative
contracts.
Subject to fluctuations in commodity prices, the Trust anticipates
that it will continue to maintain adequate liquidity to fund planned
capital spending during 2007 through a contribution of funds from
operations, funds received from its distribution reinvestment program
and bank borrowings.
ASSET RETIREMENT OBLIGATION
At June 30, 2007, the Trust reported an Asset Retirement Obligation
("ARO") balance of $64.9 million ($65.6 million at December 31, 2006)
for future abandonment and reclamation of the Trust's oil and gas
properties and facilities. The ARO balance was increased by accretion
expense of $2.6 million in the first six months of 2007 ($2.5 million in
the first six months of 2006) and reduced by $2.9 million for actual
abandonment and environmental expenditures incurred in the first six
months of 2007 ($2.0 million in the first six months of 2006).
DISTRIBUTIONS TO UNITHOLDERS
The Trust sets distributions based upon commodity prices, financial
market conditions, internal capital investment opportunities and the
resulting impact on taxability and payout ratios. The Trust develops an
annual forecast, which is updated regularly by management. The Board
sets distributions at a level it believes will be sustainable for a
period of time and formally reviews distribution levels quarterly.
For the three months ended June 30, 2007, funds from operations
amounted to $54.2 million, compared with $52.2 million for the three
months ended June 30, 2006. NAL declared cash distributions of $37.9
million ($0.48 per unit) in the second quarter as compared to $43.3
million ($0.57 per unit) in the second quarter of 2006. This represented
a 70 percent payout ratio for the quarter, compared with an 83 percent
payout ratio in the comparable quarter in 2006.
The weighted average number of units outstanding during the second
quarter of 2007 increased by four percent to 78.8 million from 75.9
million in 2006.
For the six months ended June 30, 2007, funds from operations was
$108.4 million compared with $109.9 million for the comparable period in
2006. NAL declared cash distributions of $75.5 million ($0.96 per unit)
in this period as compared to $85.9 million ($1.14 per unit) in 2006.
This represented a 70 percent payout ratio for the six months compared
to 78% in the comparable period.
Distributions
----------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Funds from operations ($000s) 54,156 52,210 108,391 109,874
Distributions declared ($000s) 37,877 43,268 75,483 85,865
Funds from operations per unit (1) $ 0.69 $ 0.69 $ 1.38 $ 1.46
Distributions declared per unit $ 0.48 $ 0.57 $ 0.96 $ 1.14
Weighted average units outstanding
(000s) 78,824 75,869 78,543 75,210
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Based on weighted average units outstanding.
VARIABLE INTEREST ENTITIES
NAL has no variable interest entities.
CONTRACTUAL OBLIGATIONS
NAL has entered into several contract obligations as part of conducting
day-to-day business. NAL has the following commitments for the next five
years:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($000s) 2007 2008 2009 2010 2011
----------------------------------------------------------------------------
Office Lease (1) 1,285 2,580 2,580 2,365 -
Transportation 727 795 795 84 -
Processing Agreement (2) 245 469 446 428 414
Drilling rigs (3) 988 494 - - -
Retention bonus (4) - 588 - - -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Represents the full amount of office lease commitments, both base rent
and operating costs, held by the Manager, of which the Trust is
allocated a pro rata share (currently approximately 52 percent) of the
expense on a monthly basis.
(2) Represents a gas processing agreement with a take or pay arrangement.
(3) Represents the Trust's share of minimum payments required under drilling
rig contracts held by NAL Resources.
(4) Represents the Trust's share of the expected future payments under a
staff retention program.
QUARTERLY INFORMATION
2007 2006
----------------------------------------------------------------------------
($000s, except per unit
and production amounts) Q2 Q1 Q4 Q3 Q2 Q1
----------------------------------------------------------------------------
Revenue, net of
royalties 83,268 71,231(2) 75,694 75,798 77,988 81,272
Per unit 1.06 0.91 0.97 0.98 1.03 1.08
Funds from
operations(1) 54,156 54,234 55,795 54,107 52,210 57,664
Per unit 0.69 0.69 0.72 0.70 0.69 0.77
Net income 21,390 16,710 20,472 20,473 (5,357)(3) 24,610
Per unit 0.27 0.21 0.26 0.27 (0.07) 0.33
Average oil equivalent
production (boe/d-6:1) 18,946 19,422 19,517 19,079 19,012 20,181
----------------------------------------------------------------------------
QUARTERLY INFORMATION
2005
----------------------------------------------------------------------------
($000s, except per unit
and production amounts) Q4 Q3
----------------------------------------------------------------------------
Revenue, net of royalties 95,643 85,613
Per unit 1.30 1.18
Funds from operations(1) 65,837 62,442
Per unit 0.90 0.86
Net income 30,777 31,710
Per unit 0.42 0.44
Average oil equivalent production (boe/d-6:1) 20,514 19,710
----------------------------------------------------------------------------
(1) Represents cash flow from operating activities prior to the change in
non-cash working capital items.
(2) Includes unrealized loss on derivative instruments due to implementation
of new accounting standards Jan 1, 2007.
(3) Includes non-cash management restructuring fee of $27.2 million.
FINANCIAL REPORTING DISCLOSURE CONTROLS
Management has evaluated the effectiveness of the Trust's financial
reporting disclosure controls and procedures as at June 30, 2007, and
has concluded that such financial reporting disclosure controls and
procedures were effective as at that date.
CHANGES TO INTERNAL CONTROL OVER FINANCIAL REPORTING
There were no changes to the Trust's internal control over financial
reporting since December 31, 2006 that have materially affected, or are
reasonably likely to materially affect, the Trust's internal control
over financial reporting.
CRITICAL ACCOUNTING ESTIMATES
The significant accounting policies used by NAL are disclosed in the
notes to NAL's December 31, 2006 audited consolidated financial
statements. Certain accounting policies require that management make
appropriate decisions when formulating estimates and assumptions that
affect the reported amounts of assets, liabilities, revenues and
expenses. The Manager reviews the estimates regularly. The emergence of
new information and changed circumstances may result in actual results
or changes to estimated amounts that differ materially from current
estimates. NAL might realize different results from the application of
new accounting standards published, from time to time, by various
regulatory bodies. An assessment of NAL's significant accounting
estimates is discussed in the MD&A filed with NAL's audited
consolidated financial statements for the year ended December 31, 2006.
NEW ACCOUNTING POLICIES
Effective January 1, 2007 the Trust implemented the provisions of
CICA Handbook Section 3855 "Financial Instruments - recognition and
measurement", Section 3861 "Financial Instruments - disclosure and
presentation", Section 3865 "Hedges", Section 1530 "Comprehensive
Income", and certain provisions of Section 3251 "Equity".
These standards address the recognition and measurement of financial
assets, financial liabilities and non-financial derivatives. Financial
instruments are classified into one of four categories, each category
determines how an instrument is measured and when and where gains and
losses are recognized. Instruments are either measured at fair value or
amortized cost, which is determined using the effective interest method.
The hedging standard provides guidance on when and how hedge accounting
may be performed and section 1530 provides standards on the reporting
and display of comprehensive income and its components.
These standards have been applied by the Trust, on a prospective
basis, in accordance with the relevant transitional provisions. For full
details on the implications to the Trust of these standards, see Note 2
to the interim consolidated financial statements.
FUTURE ACCOUNTING CHANGES
The CICA issued new accounting standards; Section 1535 "Capital
Disclosures", Section 3862 "Financial Instruments - Disclosures", and
Section 3863 "Financial Instruments - Presentation". These standards
will be effective January 1, 2008.
Section 1535 "Capital Disclosures" establishes standards for
disclosing information about an entity's capital and how it is managed.
The Section specifies disclosure about objectives, policies and
processes for managing capital, quantitative data about what the entity
regards as capital, whether the entity has complied with any capital
requirements, and if it has not complied, the consequences of such
non-compliance.
Section 3862 and 3863, establish standards to revise and enhance
disclosure on financial instruments. These standards require entities to
provide disclosure in their financial statements that enable users to
evaluate the significance of financial instruments to the entity's
financial position and performance, and the nature and extent of risks
arising from financial instruments and how the entity manages those
risks. The standards establish presentation guidelines for financial
instruments and non-financial derivatives and deals with the
classification of financial instruments from the perspective of the
issuer, between liabilities and equity, the classification of related
interest, dividends, losses and gains, and the circumstances in which
financial assets and liabilities are offset.
The Trust has not yet assessed the impact of these standards on its financial statements.
Dated: July 30, 2007
CONSOLIDATED BALANCE SHEETS
(thousands of dollars) (unaudited)
As at June 30, 2007 As at December 31, 2006
----------------------------------------------------------------------------
Assets
Current assets
Cash and cash equivalents $ 5,069 $ 6,295
Accounts receivable and other 49,223 44,467
Derivative contracts (Note 2) 2,923 -
----------------------------------------------------------------------------
57,215 50,762
Future income tax asset 3,071 3,345
Property, plant and
equipment, net 719,167 742,795
----------------------------------------------------------------------------
$ 779,453 $ 796,902
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Liabilities and
Unitholders' Equity
Current liabilities
Accounts payable and
accrued liabilities $ 30,529 $ 40,563
Distributions payable to
unitholders 12,654 12,475
Derivative contracts (Note 2) 2,786 -
----------------------------------------------------------------------------
45,969 53,038
Bank debt (Note 3) 233,517 220,785
Unit-based incentive
compensation (Note 4) 1,570 1,005
Asset retirement
obligations (Note 5) 64,887 65,574
----------------------------------------------------------------------------
345,943 340,402
Unitholders' equity (Note 6)
Unitholders' capital 838,152 824,986
Deficit (405,869) (368,486)
Accumulated other
comprehensive income 1,227 -
----------------------------------------------------------------------------
Deficit and accumulated
other comprehensive income (404,642) (368,486)
----------------------------------------------------------------------------
Unitholders' equity 433,510 456,500
----------------------------------------------------------------------------
Liabilities and
unitholders' equity $ 779,453 $ 796,902
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Units outstanding (000s) 79,086 77,971
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes
CONSOLIDATED STATEMENTS OF INCOME, COMPREHENSIVE INCOME AND DEFICIT
(thousands of dollars, except per unit amounts) (unaudited)
----------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Revenue
Oil, natural gas and liquids
sales $ 96,675 $ 95,497 $ 191,111 $ 199,050
Crown royalties (14,757) (13,908) (29,786) (32,072)
Freehold and other royalties (5,960) (5,227) (11,491) (11,119)
----------------------------------------------------------------------------
75,958 76,362 149,834 155,859
Gain (loss) on derivative
contracts (Note 2):
Realized gain 848 647 3,122 893
Unrealized gain (loss) 3,366 - (4,384) -
Reclassification from other
comprehensive income 1,394 - 2,773 -
----------------------------------------------------------------------------
5,608 647 1,511 893
Royalty and other income 1,702 979 3,154 2,508
----------------------------------------------------------------------------
83,268 77,988 154,499 159,260
----------------------------------------------------------------------------
Expenses
Operating 14,952 16,666 29,078 30,903
Transportation costs 594 636 1,191 1,304
General and administrative 3,844 3,464 7,759 5,928
Unit-based incentive
compensation (Note 4) 688 595 664 2,433
Management fees - 600 - 1,350
Restructuring fee - 27,299 - 27,299
Interest on bank debt 3,137 2,338 5,996 4,708
Depletion, depreciation and
amortization 34,822 31,236 69,250 64,141
Accretion on asset
retirement obligations 1,302 1,240 2,599 2,479
----------------------------------------------------------------------------
59,339 84,074 116,537 140,545
----------------------------------------------------------------------------
Income (loss) before taxes 23,929 (6,086) 37,962 18,715
Income and capital taxes
(provision) (84) (478) (108) (616)
Future income tax reduction
(provision) (2,455) 1,207 246 1,154
----------------------------------------------------------------------------
Total income and capital
taxes (provision) (2,539) 729 138 538
----------------------------------------------------------------------------
Net income (loss) 21,390 (5,357) 38,100 19,253
Other comprehensive income:
Reclassification to net
income, net of tax (Note 2) (979) - (1,946) -
----------------------------------------------------------------------------
Comprehensive Income 20,411 (5,357) 36,154 19,253
----------------------------------------------------------------------------
Deficit, beginning of period (389,382) (277,082) (368,486) (259,095)
Net income (loss) 21,390 (5,357) 38,100 19,253
Distributions declared (37,877) (43,268) (75,483) (85,865)
----------------------------------------------------------------------------
Deficit, end of period $ (405,869) $ (325,707) $ (405,869) $ (325,707)
----------------------------------------------------------------------------
Net income (loss) per Trust
unit $ 0.27 $ (0.07) $ 0.49 $ 0.26
----------------------------------------------------------------------------
Weighted average units
outstanding (000s) 78,824 75,869 78,543 75,210
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes
CONSOLIDATED STATEMENTS OF CASH FLOWS
(thousands of dollars) (unaudited)
----------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Operating Activities
Net income (loss) $ 21,390 $ (5,357) $ 38,100 $ 19,253
Items not involving cash:
Depletion, depreciation and
amortization 34,822 31,236 69,250 64,141
Accretion on asset retirement
obligations 1,302 1,240 2,599 2,479
Unrealized (gain) loss on
derivative contracts (3,366) - 4,384 -
Reclassification from other
comprehensive income (1,394) - (2,773) -
Future income tax provision
(reduction) 2,455 (1,207) (246) (1,154)
Restructuring fee - 27,159 - 27,159
Abandonment and environmental
expenditures (1,053) (861) (2,923) (2,004)
Change in non-cash working
capital 1,865 8,011 596 19,144
----------------------------------------------------------------------------
56,021 60,221 108,987 129,018
----------------------------------------------------------------------------
Financing Activities
Distributions to unitholders (37,789) (42,904) (75,305) (85,276)
Issue of Trust units, net of
issue costs 6,608 6,049 13,165 26,856
Increase (decrease) in bank
debt 3,884 (6,768) 12,732 (29,194)
Change in non-cash working
capital - 1,062 915 744
----------------------------------------------------------------------------
(27,297) (42,561) (48,493) (86,870)
----------------------------------------------------------------------------
Investing Activities
Additions to property, plant
and equipment (18,925) (24,669) (46,009) (44,681)
Proceeds from dispositions - - 25 123
Reclamation reserve - (198) - (294)
Change in non-cash working
capital (9,853) 17,149 (15,736) 12,230
----------------------------------------------------------------------------
(28,778) (7,718) (61,720) (32,622)
----------------------------------------------------------------------------
Increase (decrease) in cash
and cash equivalents (54) 9,942 (1,226) 9,526
Cash and cash equivalents,
beginning of period 5,123 708 6,295 1,124
----------------------------------------------------------------------------
Cash and cash equivalents,
end of period $ 5,069 $ 10,650 $ 5,069 $ 10,650
----------------------------------------------------------------------------
Supplementary disclosure of
cash flow information:
Cash paid during the period
for:
Interest $ 3,069 $ 2,299 $ 5,900 $ 4,632
Taxes $ 84 $ 478 $ 108 $ 616
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Six months ended June 30, 2007
(Tabular amounts in thousands of dollars, except per unit amounts)(unaudited)
1. SUMMARY OF ACCOUNTING POLICIES
Management prepared the interim consolidated financial statements of
NAL Oil & Gas Trust ("NAL" or the "Trust") in accordance with
accounting principles generally accepted in Canada and following the
same accounting policies and methods of computation as the consolidated
financial statements for the fiscal year ended December 31, 2006, except
for the implementation of new standards addressing financial
instruments, hedging and comprehensive income as described below. The
following disclosure is incremental to the disclosure included within
the annual financial statements. Please read the interim consolidated
financial statements in conjunction with the consolidated financial
statements and notes thereto in NAL's annual report for the year ended
December 31, 2006.
Financial Instruments, Hedges, Comprehensive Income
Effective January 1, 2007 the Trust implemented the provisions of
CICA Handbook Section 3855 "Financial Instruments - recognition and
measurement", Section 3861 "Financial Instruments - disclosure and
presentation", Section 3865 "Hedges", Section 1530 "Comprehensive
Income" and certain provisions of Section 3251 "Equity".
Section 3855 establishes standards for recognizing and measuring
financial assets, financial liabilities and non-financial derivatives.
Financial instruments are classified into one of four categories, each
category determines how an instrument is measured and when and where
gains and losses are recognized. Instruments are either measured at fair
value or amortized cost, which is determined using the effective
interest method. Section 3865 provides guidance on when and how hedge
accounting may be used. Section 1530 provides standards on the reporting
and display of comprehensive income and its components. Other
comprehensive income comprises revenues, expenses, gains and losses not
included in net income. Section 3251 provides guidance on the
presentation and disclosure of the components of equity, including
accumulated other comprehensive income.
These standards have been applied on a prospective basis, in accordance with the relevant transitional provisions.
The Trust has entered into certain derivative contracts in order to
reduce its exposure to market risks from fluctuations in commodity
prices. In accordance with Section 3855, all derivative instruments are
recorded on the balance sheet at fair value, with changes in the fair
value recognized in net income, unless specific hedge criteria are met.
The Trust has not designated its derivative contracts as effective
accounting hedges under Section 3865, even though the Trust considers
all commodity contracts to be effective economic hedges. Therefore,
changes in the fair value of the derivative instruments are recognized
in net income for the period.
On January 1, 2007, the Trust had derivative contracts in place with
a fair value of $4.5 million. The transitional provisions of the new
standards allow for NAL's derivatives to be recorded as an asset on
January 1, 2007 with the offset being recorded in accumulated other
comprehensive income ("AOCI"), a component of unitholders' equity. The
amount recorded in AOCI will be reclassified to net income over the
remaining term of the derivatives.
Accordingly, on January 1, 2007, the fair value of the derivatives
of $4.5 million was recorded as an asset on the balance sheet with a
corresponding increase in accumulated other comprehensive income
("AOCI").
The fair value of these derivative instruments is based on an
approximation of the amounts that would be received or paid to settle
these instruments at the end of the period, with reference to forward
prices and market valuations provided by third party sources.
In accordance with Section 3855, bank debt is presented net of
deferred interest payments, with interest recognized in net income on an
effective interest basis. Previously, interest was recognized on a
straightline basis with the deferred amount included in accounts
receivable. There was no impact at January 1, 2007 resulting from this
change.
2. DERIVATIVE CONTRACTS AND RISK MANAGEMENT
Commodity Price Risk Management
NAL employs risk management practices to assist in managing cash
flows and support capital programs and distributions. NAL's management
is authorized to hedge up to 50% of its annual net production. NAL's
risk management programs tend to be scaled-in over time using a
combination of swaps and collars.
As at June 30, 2007, the Trust had entered into the following
derivatives to protect its 2007 cash flow from the volatility of oil and
natural gas commodity prices.
For the balance of 2007, NAL has the following WTI oil contracts in place:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total
Volume Volume Bought Put Sold Call Swap
----------------------------------------------------------------------------
Term Contract Bbls/d Bbls US$/bbl US$/bbl US$/bbl
----------------------------------------------------------------------------
COLLARS
July-Dec 2-way 500 92,000 62.00 68.25 -
July-Dec 2-way 200 36,800 64.00 71.00 -
July-Dec 2-way 300 55,200 62.00 69.75 -
July-Dec 2-way 200 36,800 63.00 68.50 -
July-Dec 2-way 200 36,800 62.50 69.50 -
July-Dec 2-way 200 36,800 64.00 70.45 -
July-Dec 2-way 100 18,400 66.00 72.25 -
July-Dec 2-way 100 18,400 67.00 71.75 -
July-Dec 2-way 100 18,400 68.00 71.50 -
July-Dec 2-way 100 18,400 68.00 72.00 -
Aug-Dec 2-way 100 15,300 71.00 74.50 -
----------------------------------------------------------------------------
Weighted Average Collars 383,300 63.90 70.03 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
SWAPS
July-Dec Swap 100 18,400 - - 69.10
July-Dec Swap 500 92,000 - - 65.05
July-Dec Swap 500 92,000 - - 72.33
July-Dec Swap 300 55,200 - - 61.07
July-Dec Swap 100 18,400 - - 69.00
July-Dec Swap 100 18,400 - - 69.30
July-Dec Swap 100 18,400 - - 70.14
Aug-Dec Swap 100 15,300 - - 72.80
----------------------------------------------------------------------------
Weighted Average Swaps 328,100 - - 67.76
----------------------------------------------------------------------------
----------------------------------------------------------------------------
For the balance of 2007, NAL has the following AECO natural gas contracts
in place:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total
Volume Volume Bought Put Sold Call Swap
----------------------------------------------------------------------------
Term Contract GJ/d GJ Cdn$/GJ Cdn$/GJ Cdn$/GJ
----------------------------------------------------------------------------
COLLARS
July-Dec 2-way 3,000 552,000 6.00 8.10 -
July-Dec 2-way 1,000 184,000 6.50 8.85 -
July-Dec 2-way 1,000 184,000 7.00 8.70 -
July-Dec 2-way 1,000 184,000 6.75 8.60 -
July-Dec 2-way 2,000 368,000 7.00 8.70 -
July-Dec 2-way 1,000 184,000 7.25 8.51 -
----------------------------------------------------------------------------
Weighted Average Collars 1,656,000 6.61 8.48 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
SWAPS
July-Dec Swap 3,000 552,000 - - 6.77
July-Dec Swap 1,000 184,000 - - 7.90
July-Dec Swap 1,500 276,000 - - 7.20
July-Dec Swap 1,500 276,000 - - 7.43
----------------------------------------------------------------------------
Weighted Average Swaps 1,288,000 - - 7.16
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NAL currently has the following WTI oil contracts in place for fiscal 2008:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total
Volume Volume Bought Put Sold Call Swap
----------------------------------------------------------------------------
Term Contract Bbls/d Bbls US$/bbl US$/bbl US$/bbl
----------------------------------------------------------------------------
COLLARS
January-June 2-way 200 36,400 64.00 72.26 -
January-March 2-way 100 9,100 66.00 71.90 -
January-June 2-way 200 36,400 68.50 73.00 -
January-June 2-way 100 18,200 70.00 76.25 -
April-June 2-way 100 9,100 69.00 74.25 -
January-March 2-way 100 9,100 68.00 73.60 -
January-March 2-way 100 9,100 68.00 74.35 -
January-June 2-way 100 18,200 69.00 74.00 -
January-June 2-way 100 18,200 70.00 75.05 -
January-June 2-way 100 18,200 70.00 75.00 -
----------------------------------------------------------------------------
Weighted Average Collars 182,000 67.95 73.79 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
SWAPS
January-March Swap 100 9,100 - - 69.35
January-March Swap 100 9,100 - - 71.30
January-June Swap 100 18,200 - - 73.47
January-June Swap 100 18,200 - - 72.50
April-June Swap 100 9,100 - - 71.90
----------------------------------------------------------------------------
Weighted Average Swaps 63,700 - - 72.07
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NAL currently has the following AECO natural gas contracts in place for
fiscal 2008:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total
Volume Volume Bought Put Sold Call Swap
----------------------------------------------------------------------------
Term Contract GJ/d GJ Cdn$/GJ Cdn$/GJ Cdn$/GJ
----------------------------------------------------------------------------
COLLARS
January-March 2-way 2,000 182,000 8.40 10.25 -
January-March 2-way 1,000 91,000 8.40 10.15 -
January-March 2-way 1,000 91,000 8.40 10.40 -
January-March 2-way 1,000 91,000 8.00 9.40 -
----------------------------------------------------------------------------
Weighted Average Swaps 455,000 8.32 10.09 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
SWAPS
January-March Swap 1,000 91,000 - - 8.90
January-March Swap 1,500 136,500 - - 7.20
January-March Swap 1,000 91,000 - - 9.13
----------------------------------------------------------------------------
Weighted Average Swaps 318,500 - - 8.24
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Fair Values
The carrying amount of the Trust's financial instruments, including
accounts receivable, accounts payable and accrued liabilities and
distributions payable, approximate their fair value due to their short
term to maturity.
The Trust's bank debt and cash equivalents bear interest at a
floating market rate and, accordingly, the fair market value
approximates the carrying amount.
Derivative contracts are recorded at fair value on the balance sheet
as current assets or current liabilities based on their fair values on a
contract by contract basis.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Six months ended June 30
2007 2006
----------------------------------------------------------------------------
Current gain on the fair value of derivative contracts $2,923 $ -
Current loss on the fair value of derivative contracts (2,786) -
----------------------------------------------------------------------------
Unrealized gain on fair value of derivative contracts $ 137 $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
On transition to Section 3865 on January 1, 2007, the fair value of
the outstanding contracts of $4.5 million was recorded in accumulated
other comprehensive income, with related tax of $1.3 million, and will
be transferred to net income over the term of the respective contracts.
During the first six months of 2007, $2.8 million has been reclassified
to net income and is included in the gain (loss) on derivative
contracts.
As at June 30, 2007, the total fair value of derivative contracts
was a gain of $137,000. The change in the fair value for the six months
of $4.4 million has been recognized as a loss in the income statement.
The following table reconciles the movement in the fair value of the
Trust's derivative contracts:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Fair value, beginning of period $(3,229) - - -
Fair value on transition to new
accounting standards (Note 1) - - $4,521 -
Fair value, end of period 137 - 137 -
----------------------------------------------------------------------------
Change in fair value of contracts
in the period 3,366 - (4,384) -
Realized gain in the period 848 647 3,122 893
Reclassification from other
comprehensive income 1,394 - 2,773 -
----------------------------------------------------------------------------
Gain on derivative contracts $ 5,608 $647 $1,511 $893
----------------------------------------------------------------------------
3. BANK DEBT
The Trust, through its subsidiary NAL Ventures Trust, maintains a
$325 million fully secured, extendible, revolving term credit facility
with a syndicate of Canadian chartered banks. This facility consists of a
$315 million production facility and a $10 million working capital
facility. The total amount of the facility is determined by reference to
a borrowing base. The borrowing base is calculated by the bank
syndicate and is a function of the net present value of the Trust's oil
and gas reserves and other assets.
The credit facility is fully secured by first priority security
interests in all present and after acquired properties and assets of the
Trust and its subsidiary and affiliated entities. The facility will
revolve until April 30, 2008 and is extendible at that time for a
further 364-day revolving period upon agreement between the Trust and
the bank syndicate. If the credit facility is not extended in April
2008, the amounts outstanding at that time will be converted to a
two-year term loan. The term loan will be payable in four equal
quarterly installments commencing May 2009 with a final residual payment
in May 2010.
Amounts are advanced under the credit facility in Canadian dollars
by way of prime interest rate based loans and by issues of bankers'
acceptances and in U.S. dollars by way of U.S. based interest rate and
Libor based loans. The interest charged on advances is at the prevailing
interest rate for bankers' acceptances, Libor loans, lenders' prime or
U.S. based rates plus an applicable margin or stamping fee. The
applicable margin or stamping fee, if any, varies based on the
consolidated debt-to-cash flow ratio of the Trust.
On June 30, 2007, the effective interest rate on amounts outstanding under the credit facility was 5.41 percent.
4. UNIT-BASED INCENTIVE COMPENSATION
The Trust recorded a compensation expense of $0.8 million in the
first six months of 2007 of which $664,000 was recorded to income and
$171,000 to capital ($2.5 million expensed and $1.7 million capitalized
for full year 2006) for the estimated cost of the plan. The compensation
expense was based on the June 30, 2007 unit price of $12.60 ($12.95 in
2006), accrued distributions, performance factors, and the number of
units vesting on maturity.
The following table reconciles the change in total accrued unit-based
incentive compensation relating to the plan:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Six months ended Year ended
June 30, 2007 December 31, 2006
----------------------------------------------------------------------------
Balance, beginning of period $4,153 $ -
Increase in liability 836 4,153
Cash payout, relating to units vested
November 30, 2006 (2,184) -
----------------------------------------------------------------------------
Balance, end of period $2,805 $4,153
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Current portion of liability 1,235 3,148
----------------------------------------------------------------------------
Long-term liability 1,570 1,005
----------------------------------------------------------------------------
----------------------------------------------------------------------------
5. ASSET RETIREMENT OBLIGATIONS
The total future asset retirement obligation was estimated by the
Manager based on the Trust's net ownership interests in oil and natural
gas assets including well sites, gathering systems and processing
facilities, estimated costs to remediate, reclaim and abandon the wells
and facilities and the estimated timing of the costs to be incurred in
future periods. NAL has estimated the net present value of its asset
retirement obligations to be $64.9 million as at June 30, 2007, based on
a total undiscounted amount of cash flows required to settle its asset
retirement obligations of $162.5 million (December 31, 2006 - $165.2
million). These costs are expected to be incurred over the next 46 years
with the majority of the costs incurred between 2007 and 2033. NAL's
credit-adjusted risk-free rate of eight percent (2006 - eight percent)
and an inflation rate of two percent (2006 - two percent) were used to
calculate the present value of the asset retirement obligations.
The following table reconciles the Trust's asset retirement obligations.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Six months ended Year ended
June 30, 2007 December 31, 2006
----------------------------------------------------------------------------
Balance, beginning of period $65,574 $61,908
Accretion expense 2,599 4,984
Liabilities incurred (363) 3,117
Liabilities settled (2,923) (4,435)
----------------------------------------------------------------------------
Balance, end of period $64,887 $65,574
----------------------------------------------------------------------------
----------------------------------------------------------------------------
6. UNITHOLDERS' EQUITY
Units Issued:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Six months ended Year ended
June 30, 2007 December 31, 2006
----------------------------------------------------------------------------
Units Amount Units Amount
----------------------------------------------------------------------------
Balance, beginning of period 77,971 $824,986 73,977 $753,585
Issued under management agreement
restructuring - - 1,592 30,000
Less: Issue expenses - - - (29)
Issued from Distribution Reinvestment
Plan 1,115 13,166 2,402 41,430
----------------------------------------------------------------------------
Balance, end of period 79,086 $838,152 77,971 $824,986
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated Other Comprehensive Income:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Six months ended Year ended
June 30, 2007 December 31, 2006
----------------------------------------------------------------------------
Balance, beginning of period $ - -
Fair value of derivative instruments on
transition to new accounting standards,
net of tax of $1,349 (Note 2) 3,172 -
Reclassification to net income in period,
net of tax of $828 (Note 2) 1,945 -
----------------------------------------------------------------------------
Balance, end of period $1,227 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Cash Distributions
The Trust is required to make a distribution of distributable cash
flow each calendar month, pursuant to the Trust Indenture. The
distributable cash flow is defined as cash flow of the Trust less a
discretionary amount, which the Trustee, upon recommendations of the
Manager, considers it necessary to retain.
TRADING PERFORMANCE
----------------------------------------------------------------------------
----------------------------------------------------------------------------
For the Quarter Ended
Price ($) 30-Jun-07 31-Mar-07 30-Jun-06 31-Mar-06
----------------------------------------------------------------------------
High 13.80 13.00 20.67 20.25
Low 11.45 10.86 18.26 16.92
Close 12.57 11.75 20.00 19.58
Volume 15,594,573 16,390,680 11,319,677 13,614,737
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NAL Oil & Gas Trust is an open-end investment trust that
generates distributions through the acquisition, development, production
and marketing of oil, natural gas and natural gas liquids. The Trust
owns high quality assets in Alberta, Saskatchewan and Ontario. Trust
units trade on the Toronto Stock Exchange under the symbol "NAE.UN".
Contact Information:
NAL Oil & Gas Trust
Gordon Currie
Manager, Investor Relations
(403) 294-3620 or Toll Free: 1-888-223-8792
(403) 515-3407 (FAX)
Email: Investor.Relations@nal.ca
Website: www.nal.ca